Note: Descriptions are shown in the official language in which they were submitted.
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A SYSTEM AND METHOD FOR DETERMINING
FORCES ON A LOAD-BEARING TOOL IN A WELLBORE
Background
This invention relates to a system and method for determining forces on a load-
bearing tool in a wellbore in a downhole oil and gas recovery operation
system.
An example of a load-bearing tool of the above type is a retrievable packer
that is
inserted in a wellbore in many oil field applications for the purpose of
sealing against the
flow of fluid and thus isolate one or more portions of the wellbore for the
purposes of treating
or producing the well. The packer is suspended from a workstring, or the like,
in the
wellbore, and includes one or more elastomer elements which are activated, or
set, so that the
elements are forced against an inner surface of the wellbore, or casing, and
compressed to
seal against the flow of fluid and therefore to permit isolation of certain
zones in the well.
The packer can be set by either setting down weight through the workstring
which imparts a
compressive load to the packer or by picking up on the workstring which
imparts a tensile
load to the packer. These setting loads or setting forces are referred to as a
direct force.
After being set in the above manner, the packer can be subjected to various
additional
forces such as those related to workstring pressure and/or annulus pressure or
by thermal
expansion and contraction that occur when various fluids are pumped down the
workstring.
Since these forces may change the setting force on the packer and may
otherwise adversely
affect its operation, it is important that these additional forces be measured
and their values
either stored or transmitted to the surface in real time so as to permit
remedial action.
To this end, strain gauges have been used to measure the direct force.
However, strain
gauges are sensitive to other conditions in the wellbore that can cause the
additional forces on
the packer. Therefore, the strain gauges measure a total force that is the sum
of the direct
force and the additional forces instead of measuring only the desired direct
force.
In order to correct for this, various forms of mechanical and hydraulic
devices have
been used in an effort to compensate for the above additional forces caused by
the other
conditions in the wellbore. However, these compensation systems require
additional
components that can increase the length, complexity and cost of the system.
Therefore, what is needed is a system that compensates for the above
additional forces
while requiring few or no additional components.
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Brief Description of the Drawings
Fig. 1 is an schematic/elevational view of a downhole tool including an
embodiment
of a system according to the invention.
Fig. 2 is a partial schematic, enlarged, side view of the embodiment of Fig.
1.
Fig. 3 is a schematic view of the electronics used in the embodiment of Fig.
1.
Detailed Description
Referring to Fig. 1, the reference numeral 10 refers to a wellbore penetrating
a
subterranean ground formation F for the purpose of recovering hydrocarbon
fluids from the
formation F. A load-bearing tool 12 is lowered into the wellbore 10 to a
predetermined depth
by a workstring 14, which can be in the form of coiled tubing, jointed tubing,
drill pipe, or the
like, which is connected to the upper end of the tool 12. The tool 12 is shown
generally in
Fig. 1 and will be described in detail later.
The workstring 14 extends from a rig 16 located above ground and extending
over the
wellbore 10. The rig 16 is conventional and, as such, includes support
structure, a motor
driven winch, or the like, and other associated equipment for lowering the
tool 12, via the
workstring 14, to a predetermined depth in the wellbore 10.
The upper portion of the wellbore 10 can be lined with a casing 20 which is
cemented
in the wellbore 10 by introducing cement in an annulus formed between the
inner surface of
the wellbore 10 and the outer surface of the casing 20, all in a conventional
manner. A
production tubing 22 having a diameter greater than that of the tool 12, but
less than that of
the casing 20, may also be installed in the wellbore 10 in a conventional
manner and extends
from the ground surface to a predetermined depth in the casing 20.
As viewed in Fig. 2, the tool 12 has an upper portion 12a that supports a
series of
sensing and measuring devices that will be described, and a lower portion that
is in the form
of a packer 12b.
When actuated, or set, the tool 12 engages the corresponding inner wall
portion of the
casing 20 for the purpose of sealing against the passage of fluids across the
tool 12.
A series of sensors 34 are mounted to the upper portion 12a of the tool 12 to
sense a
direct force. Each sensor 34 can be in the form of a metal foil strain gauge
whose resistance
varies in response to various forces applied thereto, which forces are largely
in the form of
tensile and compressive stresses on the tool 12 caused by setting the tool 12.
Although only
four sensors 34 are shown, it is understood that this number can vary.
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As stated above, the sensors 34 are sensitive to other conditions in the
wellbore 10
that can cause additional forces to act on the tool 12. Examples of these
conditions include
the temperature in the wellbore 10, pressure in the workstring 14, and/or
differential pressure
across the tool 12. To compensate for this a series of pressure gauges 36 and
temperature
gauges 38 are also mounted to the upper portion 12a of the tool 12. The gauges
36 and 38 can
be in the form of piezo-resistive transducers, or any other conventional
design, and, as such,
are adapted to measure the pressure and temperature conditions in the wellbore
10 that affect
the tool 12, and output corresponding signals. Although only two pressure
gauges 36 and two
temperature gauges 38 are shown mounted to the tool 12, it is understood that
this number
can vary. Pressure gauges 36 may for example be located in a cavity in the
tool 12 and
connected by ports to the interior of the workstring 14 and an annulus formed
between the
outer surface of the tool 12 and the inner wall portion of the casing 20.
A processor 40 is also mounted to the upper portion 12a of the tool 12, and,
as shown
in Figs. 2 and 3, is electrically connected to the sensors 34 and the gauges
36 and 38. The
processor 40 receives the above output signals from the sensors 34 and the
gauges 36 and 38
and processes them in a manner to be described.
In operation, the tool 12 is lowered to a predetermined depth in the wellbore
10 via
the workstring 14, and the packer 12b is then set in a conventional manner. In
performing this
sealing function, the tool 12 is subjected to various forces, described below,
in connection
with the oil recovery process.
The sensors 34 sense a total force acting on the tool 12 and output
corresponding
signals to the processor 40. This total force includes the direct force on the
tool 12 caused by
setting the tool 12. However, the sensors 34 also sense the additional forces
caused by other
conditions in the wellbore 10 such as forces caused by thermal expansion and
contraction that
occur when various fluids are pumped down the workstring 14.
In order to determine these additional forces, the gauges 36 and 38 can
measure the
pressure in the workstring 14, the differential pressure across the tool 12,
and/or the
temperature in the wellbore 10 around the tool 12 and output corresponding
signals to the
processor 40.
The processor 40 includes a readable medium, or software, including
instructions for
execution by the processor 40, for calculating the direct force on the tool 12
from the total
force and the additional forces in accordance with well known engineering
principles. The
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additional force components are subtracted from the total force on the tool 12
measured by
the sensors 34 to arrive at the direct force on the tool 12. The processor 40
then stores data
based on these forces for downloading after the tool 12 is removed from the
well, or the
processor 40 can be designed to output a corresponding signal that is
transmitted to the rig 16
in any conventional manner. This data is collected at the rig 16 and used to
determine if the
direct force caused by setting the tool 12 is such that remedial action is
required.
It is understood that variations may be made in the foregoing without
departing from
the scope of the invention. Examples of some variations are as follows:
( 1 ) The number, the particular type, location, and the relative orientation,
of the
sensors 34 and the gauges 36 and 38 can be varied within the scope of the
invention.
(2) The gauges 36 and 38 are merely examples of measuring devices that can be
used to measure the other conditions in the wellbore 10 that cause the
additional forces on the
tool 12, and therefore other devices can be used.
(3) Only one of the gauges 36 and 38 can be used to the exclusion of the
other.
(4) The upper portion 12a of the tool 12 could be eliminated and the entire
tool 12
could be in the form of a packer, in which case the sensors 34, the gauges 36
and 38, and the
processor 40 would be mounted on the packer.
(5) The type of tool to which the sensors 34, the gauges 36 and 38, and the
processor 40 are mounted can include any load-bearing tool or sub connected to
the tool that
is insertable in the wellbore 10 in the above manner.
(6) A mandrel could be provided that is connected to, or forms part of, the
tool 12
and is adapted to receive the sensors 34, the gauges 36 and 38, and the
processor 40.
(7) The tool 12, or other load-bearing tool, can be part of a tool assembly
including other tools (not shown) for performing other operations in the
wellbore 10.
(8) The spatial references used above, such as "upward", "downward",
"vertical",
"radial", etc. are for the purpose of illustration only and do not limit the
specific orientation
or location of the structure described above.
The foregoing descriptions of specific embodiments of the present invention
have
been presented for purposes of illustration and description. They are not
intended to be
exhaustive or to limit the invention to the precise forms disclosed, and
obviously many
modifications and variations are possible in light of the above teaching. The
embodiments
were chosen and described in order to best explain the principles of the
invention and its
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practical application, to thereby enable others skilled in the art to best
utilize the invention
and various embodiments with various modifications as are suited to the
particular use
contemplated. It is intended that the scope of the invention be defined by the
claims appended
hereto and their equivalents.
